Drilling operations typically involve mounting a drill bit on the lower end of a drill pipe or “drill stem” and rotating the drill bit against the bottom of a hole to penetrate a formation, creating a borehole. A drilling fluid—typically a drilling mud—may be circulated down through the drill pipe, out the drill bit, and back up to the surface through the annulus between the drill pipe and the borehole wall. The drilling fluid has a number of purposes, including cooling and lubricating the bit, carrying the cuttings from the hole to the surface, and exerting a hydrostatic pressure against the borehole wall to prevent the flow of fluids from the surrounding formation into the borehole.
A drilling fluid with a relatively high viscosity at high shear rates can place undesirable mechanical constraints on the drilling equipment and may even damage the reservoir. Higher viscosity fluids also exert higher pressures outward on the borehole, which may cause mechanical damage to the formation and reduce the ability of the well to produce oil or gas. Higher viscosity fluids also may fracture the formation, requiring a drilling shut down in order to seal the fracture.
Damage to a reservoir is particularly harmful if it occurs while drilling through the “payzone,” or the zone believed to hold recoverable oil or gas. In order to avoid such damage, a different fluid—known as a “drill-in” fluid—is pumped through the drill pipe while drilling through the payzone.
Another type of fluid used in oil and gas wells is a “completion fluid.” A completion fluid is pumped down a well after drilling operations are completed and during the “completion phase.” Drilling mud typically is removed from the well using “completion fluid,” which typically is a clear brine. Then, the equipment required to produce fluids to the surface is installed in the well.
The viscosity of a drilling or completion brine typically is maintained using polymers, such as starches, derivatized starches, gums, derivatized gums, and cellulosics. Although these polymers are water-soluble, they have a relatively low hydration rate in brines because very little water actually is available to hydrate the polymers, particularly in high density brines.
Heating a brine to at least about 140° F. will increase the hydration rate of starches and/or other water-soluble polymers in the brine. However, heating of brine is time consuming, expensive, and difficult to achieve in the field. Plus, heating of a brine will cause starch dispersed in the brine to build excessive viscosity when subjected to high wellbore temperatures.
Less time consuming and expensive methods that will effectively hydrate water-soluble polymers in high density brines without adversely affecting downhole viscosity are sorely needed.